To accurately locate microearthquakes that are genetically related to hydraulic fracture stimulation, a thorough knowledge of the velocity structure between monitoring and fracturing treatment wells is essential. Very fast simulated annealing (VFSA) is implemented to invert for a flat-layered velocity model between wells using perforation or string-shot data. A two-point ray-tracing method is used to find the ray parameter [Formula: see text] for a ray traveling from a source to a receiver. The original traveltime-calculation formula is modified to account for the borehole source-receiver geometry. VFSA is used as a tool to optimize P- and S-wave velocities simultaneously. Unlike previous applications of VFSA, two improvements result from a new study: (1) both P- and S-wave arrival-time misfits are considered in a joint-objective function, and (2) P- and S-wave velocities are perturbed simultaneously during annealing. The inverted velocities follow the true values closely with a very small root-mean-square error, indicating the inverted model is close to the global minimum solution whose rms error should be zero for synthetic examples. Data noise contaminates inverted models, but not substantially in synthetic test results. A comparison of models inverted using VFSA and Occam’s inversion technique indicates that inverted models using VFSA are superior to those using Occam’s method in terms of velocity accuracy.

Theorectically, the perforation shot origin time T 0 affects the accuracy of the inverted velocity structure, and therefore the accuracy of subsequent microseismic event locations. The origin time can be obtained from perforation timing measurements or estimated from the picked arrival times. In order to investigate the role of origin time in velocity calibration, we designed two inversion procedures. In procedure A, T 0 is calculated during the Occam's inversion while T 0 is set to its true value in procedure B. A grid search locator is applied on both inverted models to produce two locations. We constructed three synthetic P-wave velocity models and add normally distributed random noise to the synthetic arrival times of all models. The noisy synthetic data are piped through procedure A to obtain location A and through procedure B to produce location B. Graphical analysis show that location A is closer to the true shot location than location B although both are close to each other. If we remove the data noise and repeat the test, location B is closer to the true shot than location A. It was observed that the inverted location A is better in terms of the distance from the true location if using noisy data and location B is better if using noise-free data. This indicates that uncertainties due to data noise cause our inconsistent observation and implies that perforation timing measurements are not necessary and may actually result in a less accurate velocity model.

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The results of a microseismic monitoring of a multi-stage re-fracturing treatment of a Permian Basin San Andres dolomite interval in an open-hole horizontal well will be presented in this paper. The treatment well has a horizontal well trajectory of approximately 3,000 feet within the reservoir section and had been extensively acid fractured during earlier production enhancement operations. The microseismic mapping objectives of the re-fracturing treatment for each of the stages were to characterize the azimuthal orientation of the fractures, the length of each wing, fracture height, and overall stimulation effectiveness. The study discusses mapping microseismic events in a challenging re-fracturing environment. The microseismic activities generated during a re-fracturing treatment may be very low in acoustic energy and detection may be problematic, compared to the acoustic energy released during initial hydraulic fracture propagation. In this study, few microseismic events were detected, and this data indicates that the previously propagated fractures created preferential paths for fluid flow thus reducing the propagation of a new fracture network. In fact, for the stage located the furthest from the monitor well, no microseismic events were detected. This was consistent with an Instrument Magnitude Analysis performed on the located microseismic events from the other stages that showed events further than 1,400 feet away from the monitor well were not detectable. A chemical packer was used for zonal isolation, and ball-activated sliding sleeves were used for selective injectivity for each stage along the horizontal well in the re-fracturing treatment. The operation of the sliding sleeves, for each stage and the ball drops, generated compressional and shear events which were detected by the geophone array in the monitor well. This confirmed that the instrumentation was able to detect events between the treatment well and monitor well in this job and that the microsesimic events induced during the re-stimulation treatment were at a much lower energy. The low-energy events that were located confirmed the ball-activated sleeve worked correctly and the induced fractures stayed in zone. However, the source locations detected did not delineate clear linear propagation of hydrofractures from the wellbore but described a complex fracture network. Introduction Reservoir microseismic monitoring provides insights into spatial and temporal variations in the stress field.1 Microseismic activity can be induced by stimulation, production, injection and regional tectonic processes. The microseismic mapping results for a 3,000-ft open-hole horizontal well trajectory with a stimulation treatment target of five fractures located 700 to 1000 ft apart are discussed in detail in the sections below. The target well trajectory is along a 75-ft San Andres dolomite interval possessing porosity in the range of 5–15%. The goals of the mapping were to characterize the azimuthal orientation of the fractures, the length of each wing, fracture height, and overall stimulation effectiveness. The characterization, conducted during Octocber 2006, was difficult since this portion of reservoir had been extensively acid fractured during earlier production enhancement operations, decreasing the number of microseismic events which could be located. Overview of the Permian Basin San Andres Dolomite West Welch Unit West Welch Unit is in one of four large waterflood units in the Midland Basin Welch Field in the northwestern portion of Dawson County, Texas.2 The Welch Field was discovered in the early 1940s and produces oil from a stratigraphic trap under a solution gas drive mechanism from the San Andreas Formation at approximately 4,800 ft. The field has been under waterflood for almost 40 years and a significant portion has been infill-drilled on 20-acre spacing.